Wells are generally drilled into the ground to recover natural deposits of hydrocarbons and other desirable materials trapped in geological formations in the Earth's crust. A well is drilled into the ground and directed to the targeted geological location from a drilling rig at the Earth's surface.
Once a formation of interest is reached in a drilled well, drillers often investigate the formation fluids by taking fluid samples from the formations for analysis. The analysis of a fluid sample provides information about the fluid's contents, density, viscosity, bubble point, and other important characteristics. This vital information is used for field planning decisions and for the optimization of upstream and downstream production facilities.
One fluid characteristic of particular importance is the gas-oil-ratio (“GOR”). The GOR is the ratio of the volume of the gaseous phase in the native formation fluids over the volume of liquid hydrocarbons at the standard conditions (standard conditions are 60° F. and 1 atm). Typical units for GOR are standard cubic feet of gas per barrel of oil at the standard conditions (scf/bbl), that is cubic feet of gas per barrel of oil at the standard conditions. The GOR is important in designing the upstream and downstream production facilities. For example, if the GOR is high, the surface facilities must be designed to handle a large amount of gas from the well.
Typically, a fluid sample is obtained by lowering a fluid sampling tool into the well and withdrawing a fluid sample from an underground formation. One example of a sampling tool is the Modular Formation Dynamics Tester (MDT), which is a registered trademark of Schlumberger Technology Corporation, the assignee of this invention. Formation testing tools are disclosed in U.S. Pat. Nos. 4,860,581 and 4,936,139 to Zimmerman et. al, which are assigned to the assignee of the present invention.
FIG. 1 shows a formation testing tool 101 designed to withdraw a fluid sample from a formation 114. The tool 101 is suspended in a borehole 110 on a conveyance 115 such as wireline, or multiconductor cable, that is spooled from the surface. At the surface, the wireline 115 is typically connected to an electrical control system 118 that monitors and controls the tool 101.
Once at a desired depth, the tool 101 is used to obtain a formation fluid sample. The tool 101 has a probe 120, or fluid admitting means, that is selectively extendable from the tool 101, as well as an anchoring member 121 on the opposite side of the tool 101 that is also selectively extendable. The probe 120 extends from the tool 101 and seals against the borehole wall 112 so that the probe 120 is in fluid communication with the formation 114. A typical tool 101 also includes a pump (not shown). The pump is used to pump formation fluids from the formation into the tool 101. The pump may also be used to pump formation fluids from the tool 101 into the borehole 110.
One of the problems associated with fluid sampling is that the formation fluid is typically contaminated with mud filtrate. Mud filtrate is a fluid component of the drilling fluid that seeps into the formation during the drilling process. The mud filtrate invades the formation and contaminates the native formation fluid. When a fluid sample is withdrawn from the formation, the sample will initially include mud filtrate.
To solve this problem, a fluid sample typically is withdrawn from the formation and pumped into the borehole or into a large waste chamber in the tool until the fluid being withdrawn has “cleaned up.” A “cleaned up” sample is one where the concentration of mud filtrate in the sample fluid is acceptably low so that the fluid represents the native formation fluids. At that point, a sample may be collected for later analysis.
Referring to FIG. 1 again, formation fluid is withdrawn from the formation 114 by the probe 120, and the fluid passes through a fluid analyzer 125 before it is pumped out of the tool 101 and into the borehole by a pumping means (not shown). The fluid analyzer 125 analyzes the sample fluid to determine the level of mud filtrate contamination. Once the formation fluid being withdrawn through the probe is clean, a sample may be taken by pumping the fluid sample into one of the sample chambers 122, 123.
One type of fluid analyzer used in a formation testing tool is an optical sensor, which measures the optical density (“OD”) of the sample fluid at several different wavelengths. The oil used in a oil-based mud (“OBM”) typically is light in color, thus, as the sample fluid cleans up, the OD at the color channels increases asymptotically to the OD of the darker native formation fluid.
Two types of absorption mechanism contribute to the measured OD of a fluid sample: electron excitation and molecular vibration mode excitation. Absorption by electron excitation occurs when the energy of incident light is transferred to excite delocalized pi electrons to anti-bonding states. This energy level typically corresponds to visible to near-infrared range and gives a shade of color as a result. We simply refer this mode of absorption as color hereafter in this document. Oils may exhibit different colors because they have varying amounts of aromatics, resins, and asphaltenes, each of which absorb light in the visible and near-infrared (“NIR”) spectra. Heavy oils have higher concentrations of aromatics, resins, and asphaltenes, which give them dark colors. Light oils and condensate, on the other hand, have lighter, yellowish colors because they have lower concentrations of aromatics, resins, and asphaltenes.
Molecular vibration absorption is the absorption of a particular frequency of light due to resonance of the chemical bonds in a molecule. While color absorption covers the visible and NIR spectrums, molecular vibration absorption occurs only at specific wavelengths for specific materials. For any given molecule, the wavelength at which vibration absorption occurs is related to the type of chemical bonds and the molecular structure. For example, oils have molecular vibration absorption peaks near wavelengths of 1,200 nm, 1,400 nm, and 1,700 nm. Molecular vibration absorption is a function of the concentration of the particular substance, and it is not necessarily affected by the phase of the substance. For example, the magnitude of a methane absorption resonance peak (near 1,670 nm) will be the same, regardless of whether the methane is in the gas phase or dissolved in the oil.
One type of optical sensor is the Optical Fluid Analyzer (“OFA”), which is a trademark of Schlumberger. The OFA measures the OD of the sample fluid at ten different wavelengths in the near-infrared (“NIR”) and visible range. When fluid is first withdrawn from a formation, the sample fluid is comprised of mostly light colored OBM filtrate. As the sample fluid cleans up, the sample fluid will contain more of the darker native formation fluid. The OD of the fluid sample in color channels will change as the fluid cleans up. For example, because the formation fluid is darker in color than the OBM filtrate, the OD of the fluid sample at the color channels will increase as the fluid sample is withdrawn. The OD at the color channels will asymptotically approach the OD of the formation fluid.
By taking OD data at multiple times, the OD of the native formation fluid, called the “contamination free” OD, can be mathematically determined by computing the asymptotic value of the measured OD. “Contamination free” is used herein to mean a property of the native formation fluid, substantially free of contamination from the mud filtrate. Thus, “contamination free GOR” means the GOR of the formation fluid, with no or insignificant effect from the mud filtrate. While it may be difficult in practice to obtain a fluid sample that is free of mud filtrate contamination, the goal is to determine the properties of the formation fluid. The term “apparent” is used to refer to the value of a measurement taken during a sampling process. Thus, the “apparent GOR” is the measured value of the GOR of a fluid sample that is withdrawn from the formation. The apparent GOR may be influenced by mud filtrate or other contaminants.
Once the contamination free OD is predicted, the amount of OBM filtrate contamination in the sample fluid may be determined based on the measured OD and the contamination free OD. Methods for determining the contamination of OBM in a fluid sample are disclosed, for example, in U.S. Pat. No. 5,266,800 to Mullins, which is assigned to the assignee of the present invention.
Another type of optical sensor is called the Live Fluid Analyzer (“LFA”), which is a trademark of Schlumberger. The LFA is different from the OFA because the LFA includes a methane channel at the wavelength of a “methane peak” and an oil channel at the wavelength of an “oil peak.” A “methane peak” is a molecular vibration absorption peak of methane, whose wavelength corresponds to the resonance of the CH bond in a methane molecule, One methane molecular vibration absorption peak is at a wavelength of about 1,670 nm. The molecular vibration absorption occurs independently of the color of the fluid and independently of whether the methane is in the gas phase or dissolved in the formation fluid. Similarly, an “oil peak” is a molecular vibration absorption peak of oil, whose wavelength corresponds to the resonance of the combination of —CH2 and —CH3 groups in an oil molecule. One oil peak is at a wavelength of about 1,720 nm.
Typically, OBM contains no methane, so the OD at the methane peak will increase as the fluid sample is withdrawn from the formation. The OD of the methane peak will asymptotically approach the OD at the methane peak of the formation fluid. The OD of the fluid sample at the oil channel may increase or decrease, depending on the composition of the formation fluid. Either way, it will asymptotically approach the OD at the oil channel of the formation fluid.
Another type of optical sensor is called the Condensate and Gas Analyzer (“CGA”), which is a trademark of Schlumberger. A CGA uses optical channels at specific frequencies to get a better estimate of the spectrum of gases present in a fluid sample. For example, a typical CGA has a channel that corresponds to the resonance peak for molecular vibration absorption in carbon dioxide. A typical CGA is able to determine mass concentrations of methane, non-methane gaseous hydrocarbons, carbon dioxide, and liquid hydrocarbons.
While these analyzers provide convenient methods for monitoring various components in formation fluids and, hence, the extent of the mud filtrate contamination in the formation fluids, it is desirable to have methods that are more sensitive and less influenced by pumping rates for such monitoring.